1. Field of the Invention
The present invention relates to a process for the reduction of sulfur compounds in various hydrocarbon streams and, more particularly, to a liquid-liquid extraction of a hydrocarbon liquid phase with an aqueous phase.
2. Related Art
The removal of sulfur compounds from gas streams has been of considerable importance in the past and is even more so today due to environmental considerations. Gas effluent from the combustion of organic materials, such as coal, almost always contain sulfur compounds and sulfur removal processes have concentrated on removing hydrogen sulfide since it has been considered a significant health hazard, and also because it is corrosive, particularly when water is present. With increasing emphasis on eliminating or minimizing sulfur discharge to the atmosphere, attention is now turning to the removal of other sulfur compounds from gas streams.
Numerous natural gas wells produce what is called in the industry “sour gas.” “Sour gas” is natural gas that contains hydrogen sulfide, mercaptans, sulfides and disulfides in concentrations that make its use unacceptable. Considerable effort has been expended to find an effective and cost efficient means to remove these objectionable sulfur compounds from natural gas. 
The removal of sulfur compounds and particularly chemically-combined sulfur, such as organosulfur compounds, from feedstreams is highly desirable to satisfy environmental regulations and in order to prevent potential catalyst deactivation, as well as equipment corrosion.
Typically, hydrocarbon products contain various amounts of sulfur compounds in the form of, for example, chemically-combined sulfur, such as inorganically combined sulfur and organically combined sulfur.
The presence of organosulfur compounds in hydrocarbon streams occurs naturally, as well as from the introduction of organosulfur compounds into the hydrocarbon streams during conventional processes for the production and treating of hydrocarbon products.
As previously indicated, if chemically-combined sulfur, such as organosulfur compounds, are not removed from the hydrocarbon streams, the presence of organosulfur compounds in the resultant hydrocarbon products, including natural gas, paraffins, olefins and aromatics, particularly gasoline or other fuels, can cause corrosion of processing equipment and engine parts, as well as other deleterious effects, particularly when water is present.
A number of processes are available for the removal of H2S from natural gas streams. The processes which are presently available can be categorized as those based on physical absorption, solid adsorption, or chemical reaction.
Physical absorption processes suffer from the fact that they frequently encounter difficulty in achieving the low concentrations of H2S required in the sweetened gas stream.
Solid bed adsorption processes suffer from the fact that they are generally restricted to low concentrations of H2S in the entering sour gas stream. Chemically reactive processes in general are able to meet sweet gas H2S concentration standards with little difficulty; however, they suffer from the fact that a material that will react satisfactorily with H2S, will  also react with CO2. Above all, the processes presently available do not efficiently provide for removal of mercaptans, sulfides and disulfides.
An example of a chemically reactive process is the ferric oxide fixed bed process, wherein the reactive entity is ferric oxide impregnated on an inert carrier. This process is effective for the removal of H2S, but does not appreciably remove mercaptans or other sulfur compounds. While the bed can be regenerated, the number of regenerations is limited by the build-up of elemental sulfur upon the bed.
A widely used process for removing H2S from natural gas depends upon the reactivity of H2S with amino nitrogen. (See for example U.S. Pat. No. 1,783,901, the disclosure of which is incorporated by reference.) Amine-containing chemical compounds which are currently being employed for removal of H2S from gas streams include: monoethanolamine, 2-(2-aminoethoxy)ethanol and diethanolamine. While effective for the removal of H2S, these compounds do not effectively remove mercaptans, sulfides or disulfides. Installation costs are high and operating costs are also high due to substantial energy requirements.
The Shell Oil Company's “Sulfinol” process involves both a physical solvent and a chemically reactive agent in the sweetening solution. The physical solvent involved is tetrahydrothiophene 1,1-dioxide and the amine is usually diisopropylamine. This process suffers from the disadvantage that the physical solvent has a high absorption capacity for the hydrocarbon gas constituents and the cost per unit is excessive.
In general, amine type sweetening processes tend to encounter the same kinds of operating problems, which can be roughly categorized as (a) solution loss, (b) foaming and (c) corrosion. In the presence of water, H2S is corrosive. Thus, elimination of corrosion in an amine sweetening unit is all but impossible because most amine type solvents are used in water solution. 
Activated carbon and molecular sieves are well-known, however, absorption capacities are limited. Regeneration is possible, but this requires sophisticated instrumentation and controls in addition to high energy requirements.
U.S. Pat. No. 4,035,474 to Kunkel et al., the disclosure of which is incorporated by reference, discloses a method for the removal of sulfur from tail gas by use of a cold bed absorption process. While this process utilizes a catalyst, catalyst deactivation occurs after 18 hours, and a backup unit must be brought on stream while the spent catalyst is regenerated for 12 to 14 hours at 700° F./370° C.
The reaction of alkali metal salts of sulfonamides with sulfur compounds is known. For example, a kinetic study of the reaction between sulfides and N-sodium-N-chloro-paratoluene sulfonamide is reported in the Bull. Chemical Society Japan, V.42, 2631 (1969), K. Tsujihara, et al. From the mechanistic study of this reaction, a procedure for the synthesis of sulfilimines was devised.
A process is disclosed in U.S. Pat. No. 3,756,976 to Uranek et al., the disclosure of which is incorporated by reference, which removes objectionable thiol odor from polymer latex through the use of numerous compounds that convert the odorous sulfar compounds to a nonodorous form.
The use of the alkali metal salts of N-halogenated arylsulfonamides, U.S. Pat. No. 3,756,976, teaches the use of the compounds of Uranek '976 to convert sulfur compounds to a nonodorous form and not the removal thereof. The process discloses the presence of converted sulfur compounds within the polymer latex system, but does not teach or suggest that sulfur compounds can be removed from a gas stream through the use of the alkali metal salts of N-halogenated sulfonamides. 
The reaction of sulfides with salts of N-chloroarenesulfonamides was the first method to be discovered for preparing sulfilimines. Gilchrist et al, Chem. Rev., Vol. 77, No. 3, page 409, 1977.
The reaction of Chloramine-T (trademark for N-sodium-N-chloro paratoluene sulfonamide) with thiols, disulfides, sulfides, sulfoxides and sulfones was reported by D. K. Padma et al, in Int. J. Sulfur Chem., Part A 1971, 1(4), 243-50 and titrimetric determination of mercaptans with chloramine-T is reported by R. C. Paul et al. in Talanta, 1975, 22(3), 311-12. These references do not suggest or disclose that salts of sulfonamides, such as chloramine-T can be used to remove sulfur compounds from a gas stream.
U.S. Pat. No. 4,283,373 to Frech et al., the disclosure of which is incorporated by reference, discloses a method of removing sulfur compounds from a gas stream by contacting the stream with alkali metal salts of sulfonamides. The preferred sulfonamide disclosed is chloramine-T which can be sprayed into the gas stream, or the gas can be passed through a porous carrier impregnated with the chloramine, or through a resin with pendant substituted sulfonamide groups.
U.S. Pat. No. 3,306,945 to Conviser, the disclosure of which is incorporated by reference, is directed to a process for purifying liquid unsaturated hydrocarbons by removing impurities using molecular sieve materials. This patent discloses that sulfides (R—S—R), which include dialkyl sulfides, may be adsorbed by zeolitic molecular sieves material having sufficiently large pores to capture such impurities, such as synthetic type X.
U.S. Pat. No. 4,592,892 to Eberly, Jr., the disclosure of which is incorporated by reference, discloses a process of using a sorbent catalyst to remove sulfur from naphtha. The sulfur impurities which are disclosed as being removed are mercaptans, thiophenes, disulfides, thioethers, hydrogen sulfide, carbonyl sulfide, and the like. The adsorbent is  disclosed as a Group VI B and/or Group VIII metal catalyst, for example, cobalt molybdate or nickel molybdate supported on alumina.
U.S. Pat. No. 3,367,862 to Mason et al., the disclosure of which is incorporated by reference, discloses a process for desulfurizing heavy residual petroleum fractions by contact with water in the presence of the catalyst comprising the metal, metal oxide, or metal sulfide, distended on a charred base.
Naphthas, which are used for reforming, typically contain between 50 wppm to 500 wppm sulfur as mercaptans, such as 2-propyl mercaptan, butyl mercaptan, and thiophene and hindered thiophenes, such as 2,5-dimethylthiophene. Accordingly, naphthas for reforming are usually treated with hydrogen over a hydrotreating catalyst, such as a sulfided cobalt and molybdenum on alumina support, or nickel and molybdenum on alumina support, to protect reforming catalysts. Hydrotreating converts sulfur compounds to hydrogen sulfide, decomposes nitrogen and oxygen compounds and saturates olefins. Hydrotreating is done at a temperature between about 400° F. and 900° F., a pressure between 200 psig and 750 psig, liquid hourly space velocity between 1 and 5, and hydrogen circulation rate of 500 to 3000 scf/hr. Modern hydrotreating processes can reduce the sulfur concentration in naphtha to 0.25 wppm and even to 0.1 wppm.
U.S. Pat. No. 3,898,153, the disclosure of which is incorporated by reference, is directed to purifying reformer feedstreams by passing hydrotreated reformer feedstock through a zinc oxide bed.
U.S. Pat. No. 4,634,518, the disclosure of which is incorporated by reference, passes hydrotreated reformer feed over massive nickel catalysts.
Other treatments for purifying hydrotreated feedstock for reforming are disclosed in U.S. Pat. Nos. 4,320,220, 4,225,417, 4,575,415, and 4,534,943, the disclosures of which are incorporated by reference, wherein the disclosed treatment is over manganese oxides. 
A suitable manganese oxide formulation for this purpose which is commercially available is Sulfur Guard HRD-264 sold by Englehard Industries, wherein recommended treatment conditions are temperatures within the range of 600° F. to 1000° F., pressures within the range of about 150 psig to 700 psig, 1/1 to 30/1 hydrogen to oil molar ratio, and 500 to 50,000 ghsv.
U.S. Pat. No. 4,456,527, the disclosure of which is incorporated by reference, discloses purifying a hydrotreated feed for reforming over zeolite L catalysts.
U.S. Pat. No. 5,167,797 by John D. Y. Ou and assigned to Exxon, the disclosure of which is incorporated by reference, discloses a process for removal of sulfur contaminants from hydrocarbons using processes which rely upon the reaction of organosulfur compounds with N-halogeno-compounds. The sulfur removal may be effected by using liquid/liquid extraction processes or one of two reactive adsorption processes involving injecting a stoichiometric amount of one or more N-halogeno compounds into the hydrocarbon stream and then passing the stream through an adsorbent column to adsorb the N-halogeno-sulfur compounds and any unreacted N-halogeno compounds; or using adsorbents which are pre-loaded with N-halogeno compounds which are placed in a fixed-bed column for sulfur removal.
German Patent No. 3 527 110-A to Ciba Geigy A G, the disclosure of which is incorporated by reference, discloses removing hydrogen sulfide from gases by oxidation using a solution containing anthraquinone sulphonamide and variable valency metal compounds followed by reoxidation, preferably using oxygen of hydroquinone.
The process is disclosed as being useful to purify gas, town gas, waste gases, and CO2 rich streams from coal combustion, wherein the impurities which may be present are identified as including certain oxides of C, N and S, H2S, organic S compounds, and HCN. 
British Patent No. 2 209 386 to Ciba Geigy A G, the disclosure of which is incorporated by reference, is directed to the removal of hydrogen sulfide from gases or liquid hydrocarbons by washing with alkaline solution containing anthraquinone disulphonamides. It is disclosed that hydrogen sulfide in gases is adsorbed, for subsequent removal in sulfur, by washing the gas with an aqueous alkaline solution of one or more anthraquinone sulphonamides.
European Application No. 74 894 to Cie Francaise Raffinage is directed to the extraction of hydrogen sulfide, carbon dioxide and the like, from hydrocarbon gases using sulfonamide or sulfamide as solvent. It is disclosed that undesirable gases, for example, H2S, CO2, COS, and mercaptans, are removed from their mixtures with hydrocarbons and/or H2 by a solvent whose molecule contains at least one group N—SO2, and, preferably a sulfonamide or sulfamide.